As the price of natural gas for use as fuel and chemical feedstock increases, new reserves of natural gas have regained considerable attention. However, many of the new reserves have relatively high percentages of acid gases, and especially carbon dioxide, while having relatively low percentage of desired hydrocarbons. Therefore, separation of carbon dioxide from natural gas has become critical to an economically attractive use of new natural gas reserves, and various methods and configurations have been developed.
In one method of separating carbon dioxide from a natural gas feed, at least a portion of the gas feed is subjected to cryogenic expansion. A typical cryogenic expansion process includes dehydration, cooling and partially condensation of the feed gas, wherein a first portion of the vapor fraction of the feed gas is turbo-expanded to the mid section of a column, and wherein a second portion is subcooled in an overhead subcooled exchanger and fed to the top of the demethanizer or deethanizer. Cryogenic processes are generally preferred due to their relatively simple configuration and relatively high efficiency. An example of a typical cryogenic process is shown in Prior Art FIG. 1, and particular configurations are described, for example, in U.S. Pat. No. 4,157,904 to Campbell et al., U.S. Pat. No. 4,690,702 to Paradowski et al., and U.S. Pat. No. 6,182,46 to Campbell et al.
However, the use of a turbo-expander in such configurations is generally limited to use of a feed gas with a relatively low CO2 content, most typically 2 mol % and less. Where the feed gas has a higher CO2 content, problems associated with CO2 freezing in the top of the demethanizer are frequently encountered. This is especially critical where relatively high ethane recovery is desired due to the low operating temperature requirements by the column overhead, which typically causes an increase in internal reflux and buildup of CO2.
To circumvent at least some of the problems with CO2 freezing, CO2 may be removed in an upstream CO2 removal unit to reduce the feed gas CO2 content before feeding to a NGL recovery plant. While CO2 removal units generally reduce difficulties associated with freezing, addition of such units requires substantial capital investment and operating costs.
In another method of separating carbon dioxide from a natural gas feed, CO2 removal from a feed gas for NGL recovery may be performed using a solvent (here: lean oil) absorption process. Lean oil absorption processes generally include a lean oil, typically a butane (or higher hydrocarbon) stream, to absorb the C2 plus hydrocarbons from the feed gas. An example of a typical lean oil absorption process is shown in Prior Art FIG. 2 and particular configurations are described, for example, in U.S. Pat. No. 6,340,429 to Minnkkinen, et al., and U.S. Pat. No. 5,687,584 to Mehra et al. Among other advantages, such processes may operate at a higher temperature, thus often avoiding CO2 freezing in the columns. However, most conventional lean oil absorption processes require substantial quantities of energy for lean oil regeneration and lean oil cooling. Furthermore, and especially where the CO2 concentration in the feed gas is relatively high, a high lean oil circulation is required to achieve a satisfactory NGL recovery. Therefore, and at least from an energy efficiency and process simplicity perspective, cryogenic turbo-expander processes are generally preferred over the lean oil absorption process.
Consequently, although various configurations and methods for NGL recovery are known, all or almost all of them suffer from one or more disadvantages. Thus, there is still a need to provide methods and configurations for improved NGL recovery.